Oil that is produced offshore is transported through pipelines as a complex mixture of oil, gas water and sand. One common flow regime is known as slug flow, in which the mixture flows intermittently along the pipelines and comprises a concentrated mass in the form of a liquid plug. Such a concentrated mass in movement is hereafter called a slug.
In multiphase pipelines/risers/well flow lines at reduced flow rates and/or changing gas oil ratio, compared to design specifications, instabilities in terms of terrain-induced and riser-induced slug flow often occur. Such a slug flow is a bulk of liquid moving in the pipeline followed by an amount of gas.
Terrain and riser-induced slug flow is often referred to as severe slugging. A publication by Yehuda Taitel, “Stability of Severe Slugging”, Int. Journal of Multiphase Flow, Vol. 12, No. 2, pp. 203–217, 1986, describes the phenomena of slugging. Terrain and riser-induced slug flow is induced periodically as liquid in terms of oil and water is accumulated in lower parts of the pipeline/riser, see FIG. 11-IV. At a certain time the liquid will restrict the passage for the gas. In this situation a small amount of gas bubbles through the liquid plug, however the main part of the gas accumulates upstream of the liquid plug which causes the pressure to increase (see FIG. 11-I). In this situation the pressure upstream of the liquid plug is equal to the pressure downstream of the liquid plug plus the hydraulic pressure across the liquid plug (applying a static force balance). But when the pressure increase upstream of the liquid plug becomes larger than the pressure increase downstream the liquid plug, the liquid plug starts moving (see FIG. 11-II), and then forms a slug, which accelerates. It should be noted that this condition might be fulfilled before the front of the liquid plug reaches the downstream maximum point in the pipeline profile.
Depending on operating conditions and pipeline profile, the slug may die out or it may be transported to the outlet of the pipeline/riser. In a situation where the tail of the liquid plug enters the vertical parts of the flow line (FIG. 11-III), a rapid increase in the liquid flow rate occurs due to the unstable situation where the pressure head, due to the liquid column, decreases. A slug is formed and the slug get transported to the outlet of the pipeline, and when the gas behind the slug escapes the pipeline/riser, the remaining liquid in the vertical parts returns to the bottom of the riser or dips in the pipeline profile. Then the whole process is repeated, and the result is an unstable multiphase flow pattern/cycle where the liquid flow rate varies from zero to a significant value, as the slug passes a fixed point in the pipeline, in a short period of time. The flow pattern is characteristic of severe slugging (terrain/riser-induced slugging). For terrain-induced slug flow the corresponding liquid plugs are caused by terrain effects reflected in the pipeline profile (offshore and onshore), whereas riser induced slug flow is caused by the pipeline leaving the seabed on its way to the surface (offshore). For long risers, special dynamic effects might occur due to phase transition from liquid to gas due to a considerable pressure decrease in the riser. Different riser shapes may also affect the dynamics in riser-induced slugging.
Unstable flow causes considerable problems for production in the upstream wells and operation of the downstream processing plant:                Large disturbances to the separator train, causing:                    Limiting separation capacity due to the need for larger operating margin to achieve the desired separation.            Poor separation (water carry over to export pipeline) due to rapidly varying separator feed rates.            Poor separation results in varying quality of water outlet from separators, causing large problems in the downstream water treatment system and possible violation of environmental restrictions.                        Large and rapidly varying compressor loads, causing:                    Inefficient compressor operation.            Limiting compression capacity due to the need for a larger margin to handle gas holdup behind the liquid.            Spurious flaring from limited compression capacity.                        Limited production from the upstream wells. The pressure variations at the pipeline or riser inlet 1 are also visible in the upstream wells, resulting in limited production from wells suffering from reduced lifting capacity.        
For gas lifted oil wells a problem referred to as casing heading might occur. Applications of gas lifted oil wells are different than slug flow in pipelines, risers and wells in the following sense:                The dynamic interactions in the casing heading are between the casing (conducting the gas to the injection point) and the tubing (flowline).        
For gas lifted wells the gas injection rate (at some point) can be utilized for control, which gives additional degree of freedom.
There are four main categories of principles for avoiding or reducing the effects of slug flow:    1. Design changes    2. Operational changes    3. Procedures    4. Control methods:            Feed forward control to separation unit        Slug choking        Active slug control        
An example of a typical slug handling technique that involves design changes is a technique that requires installation of slug catchers (onshore). Such design changes also have the disadvantage of that substantial capital investment is needed. Another example of such a technique is to increase the size of the first stage separators to provide buffer capacity. For already existing installations where problems with slug flow are present, and for compact separation units, these design changes have limited effects on flow stability. Still, using this technique, compressors may trip due to large rapid variations in the feed rates to the separators caused by unstable multiphase flow.
An example of an operational change is to choke the pipeline to such an extent that the operation point is outside the unstable flow regime. But such an operational change may have the disadvantage of decreasing the output flow to a level substantially lower than the capacity of the pipeline. Severe variations of pressure along different positions of the pipeline may also occur.
Procedures are rule-based calculations applied by the operator. These are often used during pipeline, riser or well flow line startup. Such rule-based calculations may some extent decrease the magnitude of slugging and reduce the variations in pressure in the flow-line. But a problem is that the approach with rule-based calculations may only decrease the magnitude of slugging at certain operating conditions. And the operating conditions may vary widely.
Prior art control methods include:
Feed-forward control to a separation unit process control system. In this approach the slug is coped with inside the separation unit. U.S. Pat. No. 5,256,171 shows a method, which utilizes process measurements inside the separation unit.
U.S. Pat. No. 5,544,672 shows slug choking, which utilizes measurements downstream of the point of slug generation and chokes the pipeline control valve in the presence of a slug.
By conventional control methods one usually refers to feed-forward or slug choking. Conventional control methods may reduce the negative effects of slugging and flow variations in a pipeline. A remaining problem by applying conventional control methods is to stabilize the multiphase flow in a complete flow line and not only reducing the effect of slugging at a single point of the flow line, typically the outlet of the flow line. Another problem with conventional control methods is that they have not proven to be efficient enough when it comes to stabilize multiphase flow and particularly not in flow-lines comprising remote well-head platforms and subsea wells.
In the light of the problems mentioned above, the inventor has found that there is a need for a more efficient method for stabilizing multiphase flow caused by slugging.